1. Field of the Invention
Embodiments of the present invention generally relate to an emergency disconnect system for a riserless subsea well intervention system.
2. Description of the Related Art
Subsea crude oil and/or natural gas wells frequently require workover to maintain adequate production. Workover operations may include perforating, gravel packing, production stimulation and repair of a downhole completion or production tubing. During the workover, specialized tools are lowered into the well by means of a wireline and winch. This wireline winch is typically positioned on the surface and the workover tool is lowered into the well through a lubricator and blowout preventer (BOP). Workover operations on subsea wells require specialized intervention equipment to pass through the water column and to gain access to the well. The system of valves on the wellhead is commonly referred to as a production or Christmas tree and the intervention equipment is attached to the tree with a blowout preventer (BOP).
The commonly used method for accessing a subsea well first requires installation of a BOP with a pre-attached tree running tool (TRT) for guiding the BOP to correctly align and interface with the tree. The BOP/running tool is lowered from a derrick that is mounted on a mobile offshore drilling unit (MODU), such as a drill ship or semi-submersible platform. The BOP/TRT is lowered on a segmented length of pipe called a workover riser string. The BOP/TRT is lowered by adding sections of pipe to the riser string until the BOP/TRT is sufficiently deep to allow landing on the tree. After the BOP is attached to the tree, the workover tool is lowered into the well through a lubricator mounted on the top of the riser string. The lubricator provides a sealing system at the entrance of the wireline that maintains the pressure and fluids inside the well and the riser string. The main disadvantage of this method is the large, specialized MODU that is required to deploy the riser string and the riser string needed to deploy the BOP.
FIG. 1A illustrates a prior art completed subsea well. A wellbore 10 has been drilled from a floor if of the sea 1 into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir (not shown). A string of casing (not shown) has been run into the wellbore and set therein with cement (not shown). The casing has been perforated to provide to provide fluid communication between the reservoir and a bore of the casing. A wellhead (not shown) has been mounted on an end of the casing string. A string of production tubing 10p (see FIG. 1B) may extend from the wellhead (not shown) to the formation to transport production fluid from the formation to the seafloor 1f. A packer (not shown) may be set between the production tubing 10p and the casing to isolate an annulus 10a (see FIG. 1B) formed between the production tubing 10p and the casing (not shown) from production fluid.
FIG. 1B illustrates a prior art horizontal production tree 50. The production tree 50 may be connected to the wellhead, such as by a collet, mandrel, or clamp tree connector. The tree 50 may be vertical or horizontal. If the tree is vertical (not shown), it may be installed after the production tubing 10p is hung from the wellhead. If the tree 50 is horizontal (as shown), the tree may be installed and then the production tubing 10p may be hung from the tree 50. The tree 50 may include fittings and valves to control production from the wellbore into a pipeline (not shown) which may lead to a production facility (not shown), such as a production vessel or platform. The tree 50 may also be in fluid communication with a hydraulic conduit (not shown) controlling a subsurface safety valve SSV 10v (not shown).
The tree 50 may include a head 51, a wellhead connector 52, a tubing hanger 53, an internal cap 54, an external cap 55, an upper crown plug 56u, a lower crown plug 56l, a production valve 57p, and one or more annulus valves 57u,l. Each of the components 51-54 may have a longitudinal bore extending therethrough. The tubing hanger 53 and head 51 may each have a lateral production passage formed through walls thereof for the flow of production fluid. The tubing hanger 53 may be disposed in the head bore. The tubing hanger 53 may support the production tubing 10p. The tubing hanger 53 may be fastened to the head by a latch 53l. The latch 53l may include one or more fasteners, such as dogs, and an actuator, such as a cam sleeve. The cam sleeve may be operable to push the dogs outward into a profile formed in an inner surface of the tree head 51. The latch 53l may further include a collar for engagement with a running tool (not shown) for installing and removing the tubing hanger 53.
The tubing hanger 53 may be rotationally oriented and longitudinally aligned with the tree head 51. The tubing hanger 53 may further include seals 53s disposed above and below the production passage and engaging the tree head inner surface. The tubing hanger 53 may also have a number of auxiliary ports/conduits (not shown) spaced circumferentially there-around. Each port/conduit may align with a corresponding port/conduit (not shown) in the tree head 51 for communicating hydraulic fluid or electricity for various purposes to tubing hanger 53, and from tubing hanger 53 downhole, such as for operation of the SSV. The tubing hanger 53 may have an annular, partially spherical exterior portion that lands within a partially spherical surface formed in tree head 51.
The annulus 10a may communicate with an annulus passage formed through and along the head 51 for and bypassing the seals 53s. The annulus passage may be accessed by removing internal tree cap 54. The tree cap 54 may be disposed in head bore above tubing hanger 53. The tree cap 54 may have a downward depending isolation sleeve received by an upper end of tubing hanger 53. Similar to the tubing hanger 53, the tree cap 54 may include a latch 54l fastening the tree cap to the head 51. The tree cap 54 may further include a seal 54s engaging the head inner surface. The production valve 57p may be disposed in the production passage and the annulus valves 57u,l may be disposed in the annulus passage. Ports/conduits (not shown) may extend through the tree head 51 to a tree controller (not shown) for electrical or hydraulic operation of the valves.
The upper crown plug 56u may be disposed in tree cap bore and the lower crown plug 56l may be disposed in the tubing hanger bore. Each crown plug 56u,l may have a body with a metal seal on its lower end. The metal seal may be a depending lip that engages a tapered inner surface of the respective cap and hanger. The body may have a plurality of windows which allow fasteners, such as dogs, to extend and retract. The dogs may be pushed outward by an actuator, such as a central cam. The cam may have a profile on its upper end. The cam may move between a lower locked position and an upper position freeing dogs to retract. A retainer may secure to the upper end of body to retain the cam.